CREDIT SUISSE SHALE SYMPOSIUM May 2017

Transcription

1 CREDIT SUISSE SHALE SYMPOSIUM May 2017

2 Forward-Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding the company s business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of Words such as expects, anticipates, intends, plans, believes, seeks, estimates, guidance, vision and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: the recent Delaware Basin acquisitions; estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes (including leverage ratios); estimated crude oil, natural gas and natural gas liquids ( NGLs ) reserves; the impact of prolonged depressed commodity prices, including potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities; expected capital budget allocations; operational flexibility and ability to revise development plans, either upward or downward; availability of sufficient funding and liquidity for the capital program and sources of that funding; expected net settlements on derivatives for 2017; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs expected to run and lateral lengths of wells, including the number of rigs expected to run in 2017; expected 2017 production and timing of turn-in-lines; potential for future impairments; expected expansion of gas processing systems and expected line pressure; compliance with debt covenants; impact of litigation on the results of operations and financial position and future strategies, plans and objectives, including all multi-year forecasts and activity projections through The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements made in this presentation reflect PDC s good faith judgment, such statements can only be based on facts and factors currently known to PDC. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation, the Company uses the terms outlook, projection, vision or similar terms or expressions, to indicate that it has modeled certain future scenarios. PDC typically uses these terms to indicate its current thoughts on possible outcomes relating to its business or the industry in periods beyond the current fiscal year. In addition to being subject to additional levels of uncertainty generally, forward-looking statements regarding such prospective matters do not necessarily reflect the outcomes the Company views as the most likely to occur, but instead are shown to illustrate aspects of its business in the context of a variety of scenarios it believes to be plausible. PDC urges you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors, made in the Company s Annual Report on Form 10-K for the year ended December 31, 2016, and PDC s other filings with the U.S. Securities and Exchange Commission ( SEC ), which are incorporated by this reference as though fully set forth herein, for further information on risks and uncertainties that could affect the Company's business, financial condition, results of operations and cash flows. The Company cautions you not to place undue reliance on forward-looking statements, which speak only as of the date hereof. PDC undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward looking statements are qualified in their entirety by this cautionary statement. This presentation contains certain non-gaap financial measures. A reconciliation of each such measure to the most comparable GAAP measure is presented in the Appendix hereto. We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA, and adjusted EBITDAX and "PV-10," non-gaap financial measures, for internal reporting and providing guidance on future results. These measures are not measures of financial performance under GAAP. We strongly advise investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. See the Appendix for a reconciliation of these measures to GAAP. Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses. Nonproved estimates of potentially recoverable hydrocarbons and EURs may not correspond to estimates of reserves as defined under SEC rules. Resource estimates and estimates of non-proved reserves include potentially recoverable quantities that are subject to substantially greater risk than proved reserves PDC Energy, Inc. All Rights Reserved. 05/08/2017 2

3 PDC Energy Premier Assets Provide Top-Tier Growth $3.4B Market Cap (1) Core Wattenberg 95,500 net acres 1,800 identified locations (2) 305 MMBoe proved reserves $4.5B Enterprise Value (1) 2,600 ~ Horizontal Locations Utica Shale Delaware Basin 62,500 net acres 785 identified locations (3) 33 MMBoe proved reserves 341 YE16 Proved Reserves (MMBoe) e TILs e Production (MMBoe) 40+% 2017e Annual Production Growth 05/08/2017 (1) As of 5/4/17; assumes 65.7 mm shares outstanding; (2) YE16 ~700 proved and ~1,100 probable; (3) YE16 Reflects 5,000 laterals in Eastern and Central areas and 10,000 laterals in Western area 3

4 Core Wattenberg Geology Overview

5 80 to 88 Million Years Ago Late Cretaceous Paleogeography Extensive Chalk Deposition Light blue shallow seas were areas of chalk deposition Niobrara Play 05/08/2017 5

6 80 to 88 Million Years Ago Late Cretaceous Paleogeography: Extensive worldwide chalk deposition DJ Basin 05/08/2017 6

7 Regional Niobrara Deposition Niobrara section is uniformly present across entire DJ Basin Only economically productive in certain areas of the basin 05/08/2017 7

8 Colorado Mineral Belt Wattenberg s Heat Source CMB heat flow runs continuously from southwest Colorado, thru central Colorado and extends to the plains under Core Wattenberg Field then dies out further northeast General weakness in the basement rock allowed for higher heat flow from the mantle to create these rich mineral deposits across Colorado Denver Core Wattenberg CMB heat flow responsible for creating many of the mineral rich areas across Colorado (Gold, Silver, Molybdenum) The same high heat flow that created the CMB also provided heat for concentrated hydrocarbon generation in the Core Wattenberg Field 05/08/2017 8

9 Core Wattenberg Productivity A Thermal Maturity Bull's-Eye is centered under the Core Wattenberg Field The location of the Bull s-eye is due to the high heat flow that generated substantial recoverable oil and gas across the Core Wattenberg Field Kerogen is a solid, insoluble organic material, typically consisting of algae and other plant material that is located in the source rock and is capable of generating oil and gas upon heating Thermal maturity, commonly measured by vitrinite reflectance, is the degree to which the source rock has been heated and its kerogen has been converted to recoverable oil and gas Higher Oil Mix Higher Gas Mix Core Wattenberg Resistivity mapping also aids in identifying areas where recoverable oil and gas was generated from the localized CMB high heat flow Thermal anomaly over the Wattenberg area as demonstrated by vitirnite reflectance data. After Higley & Cox, /08/2017 9

10 Wattenberg Field Stratigraphy Rocky Mountains created the current western boundary of the DJ basin Zones of basement weakness directly below Core Wattenberg Field enabled high heat-flow from the Mantle to thermally generate recoverable oil and gas from the organic rich source rocks Wattenberg discovery in early 1970 s: J Sand and Sussex/Shannon Codell and Niobrara developed in early 1980 s Over 20,000 vertical wells drilled substantial subsurface control Hydrocarbon Generation Window 05/08/

11 Depositional Setting of the Niobrara Average depth of +/- 7,200 in Core Wattenberg Field Chalky Benches created from skeletal debris of planktonic organisms deposited in shallow marine environment Organic Rich Source Rx Organic Rich Source Rx Niobrara is a source rock that generates oil and gas Inter-bedded shale and chalk intervals throughout section Including Codell, oil and gas saturated interval 300 to 350 feet thick Target Chalk benches but entire interval is productive Organic Rich Source Rx Entire interval has a fairly high density porosity of (10% - 14%); and very low permeability (<0.1md) Organic Rich Source Rx Niobrara has high storage capacity for hydrocarbons with a limited drainage area on a per well basis Codell Horizontal Target Requires multiple wells per section to adequately drain the recoverable oil and gas (tight spacing) 05/08/

12 Core Wattenberg Niobrara Composition Benches are not pure chalks, they contain abundant organics Many interbedded chalks / shales / marls make up the entire Niobrara section Niobrara outcrop in cement quarry near Lyons, CO A - Shale / Marls B - Chalk Note layered or bedded nature Lighter beds are chalk-rich Darker beds are organic-rich Freshly exposed rock smells of hydrocarbons 05/08/

13 Niobrara Gas-Oil Ratio (GOR) Discussion Niobrara GOR variation in Wattenberg critical for accurate forecasting Varying Liquids Content Across Core Areas Range of Area Inner Middle Outer Producing GOR Stable After 1-2 Years Low Niobrara GOR High 05/08/

14 Core Wattenberg Asset Overview

15 Core Wattenberg Asset Overview 2016 Strategic Acreage Trade Located in Kersey Area Net Acres 2017e TIL Breakdown (2) Outer Core ~ Acreage HBP SRL 36% MRL 29% XRL 35% Middle Core Inner Core Kersey Area Horizontal Locations (1) 305 YE16 Proved Reserves (MMBoe) e Spuds e TILs 6,800 Avg. 2017e TIL (Lateral Feet) 05/08/2017 (1) ~700 proved and ~1,100 probable locations; (2) TIL = turn-in-line; SRL = standard-reach lateral, MRL = mid-reach lateral, XRL = extended-reach lateral 15

16 Core Wattenberg Kersey Area Performance Tracking Updated Type Curves Type Well Profile Comparison (1) Pre-Trade Post-Trade 490 MBoe SRL Type Curve 800 MBoe MRL Type Curve 1,100 MBoe XRL Type Curve LDS Project (MRL) AD2017 MRL Type Curve Pad Average AD2016 SRL Type Curve Pad Average (Older Style Completion) 1Q17 Activity 29 spuds (4 SRL/11 MRL/14 XRL) 40 TILs (13 SRL/14 MRL/13 XRL) Plan to test stage spacing on select pads * Chestnut pad (SLR w/ 170 completion spacing) early results outperforming 490 MBoe type curve * Connie-Bihain Project (XRL) AD2017 XRL Type Curve Pad Average 5/5/2017 (1) Lateral feet assumptions: SRL 4,200; MRL 6,900 ; XRL 9,500 16

17 Core Wattenberg Base Case Economic Summary SRL Performance MRL Performance XRL Performance 490 MBoe SRL Type Curve 800 MBoe MRL Type Curve 1,100 MBoe XRL Type Curve Type Well CWC MM SRL $2.5 MRL XRL $3.5 $4.5 Older PDC Operated Wells EUR Gross MBoe ,100 F&D Cost (1) Per Boe $6.49 $5.79 $5.54 Updated Completion & Flowback IRR (2) % 100+% 100+% 100+% PV10 (2) MM $3.6 $6.4 $8.6 Type Curve ROI Undiscounted /08/2017 (1) F&D defined as CWC/Net Reserves per well; (2) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf flat in and NYMEX oil of $53, $55, $60, $65/bbl

18 Delaware Basin Geology Overview

19 Regional Boundaries for Wolfcamp Deposition Late Mississippian to Early Pennsylvanian timeframe ~320 million years ago Structural development of basin boundaries Diablo Platform to the west Central Basin Platform to the east Marathon Thrust to the south Northwest Shelf to the north Regional features defined the shape of the Delaware Basin and ultimately controlled the subsequent deposition of the Permian Wolfcamp interval 5/5/

20 Delaware Basin Structure Overview A WEST A EAST Delaware Basin Central Basin Platform Midland Basin Asymmetric shape with a steep flank on the eastern side contrasting with a gentle flank to the west. Multiple horizontal targets across both Midland and Delaware basins 05/08/

21 Background of Phase Windows and Heat Source Hueco Arch tilted the western portion of the Delaware Basin During Late Cretaceous & Early Tertiary Part of the greater Laramide Orogeny The Hueco Arch Uplift - Late Cretaceous & Early Tertiary (approximately 3,000 of uplift and 6,000 removal of overburden) The Laramide mountain-building event created a lateral heat source to further mature the in place Permian Wolfcamp shales Lateral Heat Source PDCE Leasehold Area Proximity to this heat source is the reason for higher gas content in Wolfcamp shales in the western portion of the basin By contrast, more oil-dominated Wolfcamp shales in the eastern portion of the basin are further from the heat source Ewing, Thomas, Erosional Margins and Patterns of Subsidence in the Late Paleozoic West Texas Basin and adjoining basins of West Texas and New Mexico, New Mexico Geological Society Guidebook, 44 th Field Conference, /08/

22 Wolfcamp Thickness and Resource Potential Gross Wolfcamp interval infers the general structural position of the Wolfcamp at the end of Wolfcamp time Stratigraphic cross section is hung on the Avalon shale This shows the depositional setting of the Wolfcamp Shale and the overlying Bone Springs interval prior to subsequent mountain-building Core Wattenberg Reference Stratigraphic Cross Section A A ~300 Total ~1,100 Total 05/08/2017 Delaware Basin Wolfcamp A NW A SE 22

23 Wolfcamp Structure After Deposition The Wolfcamp Shale Structure Map shows the effects of the younger Laramide structural movement of Hueco Uplift on the west side of the basin There is a significant change in the basin axis over time due to this uplift. The northwest southeast structural cross section (same line of section) dramatically shows the effect of the Hueco Uplift on the west side of the basin Structural Cross Section A A A NW A SE Wolfcamp Shale 05/08/

24 Delaware Basin Asset Overview

25 Delaware Basin Asset Overview 2017e Spuds Western Central Net Acres 6% 23% Eastern Average Working Interest 71% Eastern Central Western Horizontal Locations (1) e Spuds e TILs 30% YE16 HBP 3,000+ Potential Hz Locations (2) 05/08/2017 (1) YE16 Reflects 5,000 laterals in Eastern and Central areas and 10,000 laterals in Western area; (2) Based on industry tests, publicly available data, see appendix for details 25

26 Delaware Basin Area Details Commodity Mixes Represent Mid-Point of Ranges Infrastructure Assets (as of 1/1/17) 10 fresh water pits 5 salt-water-disposal wells ~60 miles of gas gathering lines ~35 miles of water gathering lines Oil Gas NGL 05/08/2017 (1) Locations are ~10,000 laterals 26

27 Delaware Basin 2017 Planned Activity $225 million D&C budget Spud 31 wells 22 spuds in Eastern 7 spuds in Central 2 spuds in Western TIL 23 wells including 14 XRLs Budgeted Well Costs (millions) Lateral Length 2/28/17 1 mile (SRL) $ miles (MRL) $8.8 2 miles (XRL) $10.5 Western PDC Phillips State Wolfcamp A ~7,500 lateral Central PDC/Fortuna HSS State Wolfcamp A (DUC) ~7,500 lateral PDC/Arris Greenwich 2 well pad - Wolfcamp A & B ~7,500 laterals Eastern $35 million midstream infrastructure Add SWD wells and capacity Drill water supply well and construct frac pits Install gas gathering lines PDC Phillips State Wolfcamp A ~7,500 lateral PDC/Arris Liam Wolfcamp B ~10,000 lateral PDC Hermit Wolfcamp B ~10,000 lateral PDC Blue Lakes Wolfcamp A ~10,000 lateral PDC Lost Saddle Wolfcamp A ~5,000 lateral PDC Elkhead Wolfcamp B ~10,000 lateral $30 million leasing, seismic & tech studies PDC/Arris Kenosha Wolfcamp A ~10,000 lateral PDC Grizzly (3) Wolfcamp B-2, A-1 ~5K -1, ~10K -2 laterals PDC/Arris Argentine Wolfcamp A ~5,000 lateral Rig Location Waiting on Completion 05/08/

28 Delaware Basin Encouraging Recent Well Results Eastern Area Wolfcamp A Early production from recent completions performing above acquisition type curve 3 wells trending ~25% above acquisition type curve 11 Wolfcamp A spuds planned in 2017 Kenosha well - ~10,000 lateral (currently in flowback, yet to reach peak production) Central Area Wolfcamp A/B Multiple wells currently on flowback (yet to reach peak production) Liam State XRL Wolfcamp B HSS State MRL Wolfcamp A Investing in compression/gathering upgrades for additional capacity in 2Q17 Acquired Legacy Central Wells 5/5/

29 Investor Relations Mike Edwards, Senior Director Investor Relations Kyle Sourk, Manager Investor Relations Corporate Headquarters PDC Energy, Inc Sherman Street Suite 3000 Denver, Colorado Website

30 APPENDIX

31 PDC Energy Strategic Overview Strategic Overview Top-Tier Growth Profile Capital Efficient Drilling Technical Innovations Marketing & Midstream Financial Discipline Shareholder Value Creation 2020 Long-Term Corporate Outlook 30+% 4-year Production CAGR ( ) ~1.0x Avg. Leverage Ratio (1) ( ) 2,600 ~ Drilling Inventory < $4 Avg. Corporate Oil Differentials (2) ($/Bbl) 80+% Weighted Avg. Portfolio IRRs 05/08/2017 (1) Leverage Ratio is defined in revolving credit facility agreement (2) Excludes Transportation, Gathering and Processing (TGP). 31

32 PDC Energy Track Record of Delivering Value 15 Oil Production (MMBbls) $25 Operating Costs ($/Boe) LOE per BOE TG&P Production Taxes G&A 10 5 $20 $15 $10 $ e $ e 9.3 MMBoe 15.4 MMBoe 22.2 MMBoe e MMBoe 05/08/

33 PDC Energy First Quarter Results 73,866 (Boe/d) 46% Year-over-Year Production Increase (MMBoe) $2.98 LOE/Boe 31% Year-over-Year Oil Prod. Increase (Bbls/d) 2017 First Quarter Highlights Continued Wattenberg execution drives strong production growth 64,285 Boe/d; 40 TILs (28 in March); 29 spuds Recently updated Wattenberg MRL and XRL type curve EURs 83% average working interest in 1Q17 Successful drilling and completions in Delaware program ~6,810 Boe/d; 3 TILs; 7 spuds TILs in both Eastern and Central area Drilled two Western area wells; one completed and on flowback Midstream investment of $6 million Continued focus on strong financial positioning Liquidity of $946 million Leverage ratio (1) of 2.0x Robust hedge positions enable preservation of margins (1) Leverage ratio is defined in revolving credit facility agreement 05/08/

34 PDC Energy 2017 Production & Capital Guidance 2017e Production (MMBoe) Anticipate Top Third of Range Production Growth Increase in Lateral Feet Drilled Wattenberg 4 th rig arrived in May ~30% annual production growth 139 Spuds 139 TILs with ~6,800 avg. lateral length 86% WI Delaware 3 rd rig added in February, Anticipate 4 th rig overlap through Sept. before returning to 3 rigs 31 Spuds 23 TILs with ~7,700 avg. lateral length 92% WI 2017e Production Mix ~22% NGL ~37% Gas ~41% Oil e Spuds e TILs ~105,000 December 17 Exit Rate (Boe/d) ~50% Year-Over-Year Increase in Oil Production 05/08/

35 PDC Energy 2017 Capital Investment Program and Financial Guidance 2017e Capital Investment (millions) YE17e Cash Balance (1) (millions) YE17e Leverage Ratio (1) Capital Investment Details Anticipate capital investment program in the top half of range Wattenberg: ~$465 MM Delaware: ~$290 MM Includes $35 MM midstream, $30MM leasing & seismic Anticipated outspend of ~$175MM Exploration and G&G (2) expense: $5-10 MM Price Realizations Oil: 92 94% Gas: 70 72% NGL: 27 31% Production tax: 6 8% of sales 2017e Capital Investments Wattenberg Delaware Delaware Midstream $ $3.00 LOE/Boe $ $3.60 G&A/Boe $ $0.90 TGP/Boe $ $16.50 DD&A/Boe 05/08/2017 (1) Includes ~$40 million proceeds from MK note. (2) G&G = Geologic and Geophysical 35

36 PDC Energy Balance Sheet Strength and Liquidity As of March 31, 2017 $946 million liquidity Leverage and Liquidity $258 million combined cash balance & short-term investments Leverage ratio (1) of 2.0x $1,000 $750 Debt Maturity Schedule (millions) Debt Maturities $700 million credit facility due May 2020 $200 million 1.125% convertible notes due Sept $500 million 7.75% senior notes due Oct $400 million 6.125% senior notes due Sept $500 $250 Corporate Ratings Moody s B1 ( Positive Outlook ) S&P B+ ( Positive Outlook ) $ Undrawn Revolver 7.75% Senior Notes 1.125% Convertible Notes 6.125% Senior Notes 5/5/2017 (1) Leverage ratio is defined in revolving credit facility agreement 36

37 PDC Energy 2020 Vision Base Case 8/24/16 Pro Forma Corporate Outlook Range 4/20/17 Corporate Outlook Range ~ Production (MMBOE) $1,800 $1,500 Adj. Cash Flow (MM) MBoe/d Exit Rate in $1,200 $900 $1.5B+ 25 $ Cash Flow < 1.0x 0 4.0x YE Rig Count (Watt./Del.) 4/3 5/5 5/6 5/7 2017e 2018e 2019e 2020e Leverage Ratio (1) $300 $0 $1,800 $1, e 2018e 2019e 2020e Capital (MM) Cash Flow Neutral in 2019 Leverage Ratio ( ) 3.0x $1,200 Base Case Pricing NYMEX Oil $53 $55 $61 $65 Gas $3.14 $3.07 $3.05 $ x 1.0x 0.0x $900 $600 $ e 2018e 2019e $0 2020e 2017e 2018e 2019e 2020e 05/08/2017 (1) Leverage ratio is defined in revolving credit facility agreement. 37

38 2020 Vision Key Outlook Factors Key Considerations Utilizes Delaware Basin acquisition type curves Potential for Wattenberg SRL type curve improvement from completion enhancements Variability of timing on first production Production range includes estimate of potential midstream constraints in Wattenberg Per well capital costs include service cost inflation Delaware midstream capital investments approximate 10% of basin D&C PDC Value Creation 05/08/

39 PDC Energy 2020 Vision Resilient Case 4/20/17 Resilient Case Range 21% 75 Production (MMBOE) $1,800 Adj. Cash Flow (MM) 4-Year Production CAGR 50 $1,500 $1,200 90% $ $ Liquidity Available ($700MM borrowing base) < 2.0x 0 4.0x YE Rig Count (Watt./Del.) 4/3 3/3 3/3 3/ Leverage Ratio (1) $300 $0 $1, Capital (MM) Leverage ratio (all years) 3.0x $1,500 $1,200 Targets Cash Flow Neutrality Stress Case Pricing 2.0x $900 NYMEX Oil $40 $40 $40 $40 1.0x $600 $300 Gas $2.50 $2.50 $2.50 $ x $ /08/2017 (1) Leverage ratio is defined in revolving credit facility agreement. 39

40 Core Wattenberg Continued Type Curve Improvements Type curve EUR increases reflect new completion design and flowback techniques XRL 30% increase to 1,100 MBoe (from 850 MBoe) MRL 15% increase to 800 MBoe (from 685 MBoe) SRL Remains at 490 MBoe 2016 TILs did not have new completion design (all SRL spuds & TILs were 1H16) 50 SRL TILs planned in SRL EUR Progression (MBoe per well) MRL XRL 1, /08/2017 (1) GOR = Gas/Oil Ratio 40

41 Core Wattenberg Growing Oil Volumes Based on Previous Analyst Day Type Curves Oil volumes per well continue to grow GOR typically stabilizes after months MRL and XRL wells represent recent completion design improvements Oil Volume per Well (1) (MBbls) SRL 490 MBoe EUR still based on 2015 completion design SRL upside projects 600 MBoe EUR (based on % improvement similar to MRL and XRL type curves) SRL upside w/ new completions SRL, MRL and XRLs represent 36%, 29% and 35% of 2017 planned Wattenberg development (TILs) XRL Wattenberg Oil Production (MMBbls) MRL SRL e /08/2017 (1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days 41

42 Wattenberg Kersey Area XRL Type Curve Increasing 30% to 1,100 MBoe Increased Type Curve from 850 MBoe Approximately 210 currently identified Middle Core locations Increased inventory driven by 2016 acreage trade Drill times average 12 days spud-to-spud Significantly enhances efficient development of Wattenberg acreage position Wattenberg XRL Performance PDC Wells Drilled Since 2016 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 1,100 MBoe XRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 1,100 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 9,500 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability 96% Capital Cost: $4.5MM IRR: 100+% PV10: $8.6MM Undiscounted ROI: 4.3 Payout (months): % 100+% 51% High GOR 30% Oil Not to scale Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

43 Wattenberg Kersey Area MRL Type Curve Increasing 15% to 800 MBoe Increased Type Curve from 685 MBoe Recently completed wells are outperforming type curve Over 380 currently identified Middle Core locations Increased inventory driven by 2016 acreage trade Drill times average 10 days spud-to-spud Wattenberg MRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 800 MBoe MRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 800 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 6,900 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability 84% Capital Cost: $3.5MM IRR: 100+% PV10: $6.4MM Undiscounted ROI: 4.2 Payout (months): % 100+% 43% High GOR 30% Oil Not to scale Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

44 Wattenberg Kersey Area SRL Type Curve of 490 MBoe Type Curve Remains 490 MBoe Most recent SRL wells completed in 1H16 using historical completion design and flowback techniques Potential upside due to new completion design being used on MRL and XRL wells Over 800 currently identified Middle Core locations Drill times average 7 days spud-to-spud Wattenberg SRL Performance PDC Wells Drilled Since 2015 in Kersey Focus Area Older PDC Operated Wells Updated Completion & Flowback 490 MBoe SRL Type Curve Base Case Type Well Details (1) 3-Phase EUR: 490 MBoe % Oil: 32% % Gas: 41% % NGL: 27% Avg. Lateral Length: 4,200 Economic Sensitivity Comparison of Type Well IRRs and GOR Variability Capital Cost: $2.5MM IRR: 100+% PV10: $3.6MM Undiscounted ROI: 3.5 Payout (months): % 100+% 60% 30% Not to scale High GOR 30% Oil Low GOR High GOR 34% Oil 30% Oil $40 / $2.50 Stress Pricing Upside Pricing (2) Low GOR 34% Oil 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf flat in and NYMEX oil of $53, $55, $60, $65/bbl ; (2) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

45 Core Wattenberg Midstream Overview Additional Capacity Enables Future Growth Objectives NATURAL GAS Multiple midstream providers (DCP and Aka-APC) DCP expected to gather and process ~72% of 2017e gas volumes DCP current capacity ~850 MMcf/d Grand Pkwy OIL Ample takeaway capacity projected through 2020 Minimal firm commitments enable competitive pricing opportunities Plant 10 Plant 11 DCP Planned Expansions (1) + 40 MMcf/d bypass (summer 2017) +200 MMcf/d plant (year-end 2018) +200 MMcf/d plant (mid-year 2019) Additional Compression Processing Capacity Expansions (1) Source: DCP Midstream press release, 1/4/17 05/08/

46 Reserves Continued Core Wattenberg Consistency 2,700 ~Wells Included in Study 2.7 Average EUR Variability Ratio for Core Wattenberg 4,200 Normalized Lateral Length Inner Core Middle Core Outer Core CO DJ Niobrara Outside Core Represents ~1,900 Hz Niobrara wells Represents ~800 Hz Niobrara wells Non-Core DJ Basin Average EUR: 190 MBoe EUR Variability (P10/P90 Ratio): 6.1 Outer Core Average EUR: 330 MBoe EUR Variability (P10/P90 Ratio): 3.3 Middle Core Average EUR: 420 MBoe EUR Variability (P10/P90 Ratio): 2.6 Inner Core Average EUR: 530 MBoe EUR Variability (P10/P90 Ratio): /08/2017 Based upon available data as of October 31, 2016, for wells in Colorado with 4+ months of production. Assumes an NGL yield of 90 Bbls/MMcf and a 20% gas shrink factor for all wells. 46

47 PDC Energy Delaware Basin Inventory Detail Acquisition Model Assumes Maximum Density of Only 12 Wells per Section Over 3,000 of Stacked Pay Potential Bench Max ACQ Spacing 1 st Bone Spg/Avalon - 2 nd Bone Spg - 3 rd Bone Spg - Wolfcamp A 8 Wolfcamp B 4 Wolfcamp C 4 Well Spacing & Inventory Summary Peer Tests Eastern Inventory (17,600 net acres) Central Inventory (28,900 net acres) Western Inventory (16,000 net acres) Wells/Sec Wells/Sec ACQ Upside ACQ Upside ACQ Upside 4-12 (XEC, CXO) 4-6 (CXO) 4-8 (NBL, CXO) 8-12 (XEC, APC) 6-8 (NBL, EGN) 6 (EGN) Total , , Acquisition Model 785 currently identified gross locations 3 main horizons Estimated 580 MMBoe of potential net reserves Potential Unrisked Upside Inventory Over 3,500 total potential gross locations 6+ potential zones across acreage Over 1 Billion Boe of potential net resource 05/08/

48 Long-Term Delaware Midstream Vision Roadmap to Incremental Value Creation Key Objectives Create separate fee structures for in-field midstream services Build out PDC midstream assets & infrastructure to support development plans 100% PDC owned Ensure competitive & reliable marketing agreements Key Evaluations Crude oil gathering systems with initial focus on Eastern area Fresh water supply distribution options and potential produced water recycling systems Explore 3 rd party volume opportunities 05/08/

49 Long-Term Delaware Midstream Vision Roadmap to Incremental Value Creation Long-Term Key Objectives Continue in-field midstream build out for PDC and potential 3 rd party volumes Continue to understand ultimate resource potential and future volume projections Evaluate options to operate and/or participate in gas processing plants and related infrastructure Potential Value Creation Strategies Maintain 100% Ownership incremental cash flows from midstream fees Joint Venture with 3 rd party midstream entity inclusive of gathering, compression & processing Potential Monetization full or partial once higher volumes established & inventory determined 05/08/

50 Delaware Basin Long-Term Vision For Driving Value Delineation Phase Development Phase 2017 HBP program Single well tests Completion design optimization & Beyond Pad development Pilot holes & additional zone testing Initial infrastructure investments Integrated facilities Delineation Cost Structure Well Type Lateral Length Capital Cost SRL 5,000 $7.1 million MRL 7,500 $8.8 million XRL 10,000 $10.5 million 10 15% Potential Improvement Development Cost Structure Well Type Lateral Length Capital Cost SRL 5,000 $6.0 million MRL 7,500 $7.5 million XRL 10,000 $9.0 million 05/08/

51 Eastern Area Wolfcamp A Outperformance Provides Upside Early production from recent completions performing above acquisition type curve 3 wells trending ~25% above acquisition type curve 11 Wolfcamp A spuds planned in 2017 Kenosha well ~10,000 lateral in Wolfcamp A Currently in flowback, yet to reach peak production Eastern Area Wolfcamp A Performance Base Case Development Type Well Details (1) 3-Phase EUR: 1,000 MBoe % Oil: 60% % Gas: 25% % NGL: 15% Avg. Lateral Length: 5,000 Capital Cost: $6.0MM IRR: 60% PV10: $5.9MM Undiscounted ROI: 3.2 Payout (months): 19 25% Performance Uplift 42% 20% Economic Sensitivity Comparison of Type Well IRRs 68% 31% 96% 48% 100+% 72% Delineation Development Delineation Development $40 / $2.50 Stress Pricing (2) Upside Pricing (3) 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Assumes 10% decrease in completed well costs; (3) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

52 Eastern Area Wolfcamp B Delivers Strong Early Results First Wolfcamp B test in Eastern area trending above acquisition type curve of 750 MBoe PDC s Triangle well currently outperforming acquisition type curve by ~25% 11 Wolfcamp B spuds planned in 2017 Eastern Area Wolfcamp B Performance Base Case Development Type Well Details (1) 3-Phase EUR: 750 MBoe % Oil: 60% % Gas: 25% % NGL: 15% Avg. Lateral Length: 5,000 Capital Cost: $6.0MM IRR: 35% PV10: $3.6MM Undiscounted ROI: 2.6 Payout (months): 30 25% Performance Uplift Economic Sensitivity Comparison of Type Well IRRs 72% 20% 9% 31% 16% 48% 28% 41% Delineation Development Delineation Development $40 / $2.50 Stress Pricing (2) Upside Pricing (3) 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Assumes 10% decrease in completed well costs; (3) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

53 Central Area Encouraging Initial Results Multiple wells currently on flowback (yet to reach peak production) Liam State XRL Wolfcamp B HSS State MRL Wolfcamp A (Fortuna DUC) Investing in compression/gathering upgrades for additional capacity in 2Q17 Central Area Wolfcamp A/B Performance Base Case Development Type Well Details (1) 3-Phase EUR: 1,050 MBoe % Oil: 40% % Gas: 35% % NGL: 25% Avg. Lateral Length: 5,000 Capital Cost: $6.0MM IRR: 34% PV10: $3.5MM Undiscounted ROI: 2.6 Payout (months): 31 Acquired Legacy Central Wells Economic Sensitivity Comparison of Type Well IRRs 27% 40% 17% 10% Delineation Development Delineation Development $40 / $2.50 Stress Pricing Upside Pricing (2) 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Assumes 10% decrease in completed well costs; (3) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

54 Western Area Acquisition Economic Summary Drill and complete two Wolfcamp A wells by 2Q17 Using 2017 completion design Will hold entire block through 2018 Consolidated acreage block conducive to longer laterals and centralized infrastructure system Western Area Wolfcamp A Performance Base Case Development Type Well Details (1) 3-Phase EUR: 1,200 MBoe % Oil: 35% % Gas: 40% % NGL: 25% Avg. Lateral Length: 10,000 Capital Cost: $9.0MM IRR: 30% PV10: $4.8MM Undiscounted ROI: 2.5 Payout (months): 33 Acquired Legacy Western Wells Economic Sensitivity Comparison of Type Well IRRs 26% 37% 9% 15% Delineation Development Delineation Development $40 / $2.50 Stress Pricing (2) Upside Pricing (3) 05/08/2017 (1) Base case pricing assumes $3.14/Mcf NYMEX gas in 2017 and ~$3.05/Mcf in and NYMEX oil of $53, $55, $60, $65/bbl in ; (2) Assumes 10% decrease in completed well costs; (3) Upside pricing assumes $3.50/Mcf NYMEX gas and $55, $60, $65, $70/bbl NYMEX oil in

55 Marketing & Midstream Gas Throughput and Processing Overview Gas delivered to both El Paso and Waha markets Added 40 MMBtu/d firm transportation basin to Waha through 2020 Eagle Claw Current capacity of ~320 MMcf/d Planned expansion in 9/17 & 1/18 total incremental 400 MMcf/d Energy Transfer (ETC) Western Western Gas Central ETC/ Undedicated 3 rd Party Midstream Central Delivery Points PDC Gas Gathering ETC in northern acreage of Central area (current capacity of ~1,000 MMcf/d) Eastern PDC owned Westeros compressor station expansion recently completed Western Gas (WES) Current capacity of ~800 MMcf/d with planned expansions at both Ramsey and Mentone facilities Acquired Assets Infrastructure Investment Asset YE16 17e Adds Total Gas Gathering (miles) Produced Water Pipeline (miles) Eagle Claw SWD Wells Compression Facilities 5 (1) 4 Fresh Water Pits /08/

56 Reconciliation of Non-U.S. GAAP Financial Measures Net income (loss) to adjusted EBITDAX Three Months Ended March 31, Net income (loss) $ 46.1 $ (71.5) Gain on commodity derivative instruments (80.7) (11.1) Net settlements on commodity derivative instruments Non-cash stock-based compensation Interest expense, net Income tax provision (benefit) 26.3 (41.8) Impairment of properties and equipment Exploration, geologic and geophysical expense Depreciation, depletion, and amortization Accretion of asset retirement obligations Adjusted EBITDAX $ $ 57.8 Weighted-average diluted shares outstanding Adjusted EBITDAX per diluted share $ 1.97 $ 1.39 Cash from operating activities to adjusted EBITDAX Three Months Ended March 31, Net cash from operating activities $ $ Interest expense, net Amortization of debt discount and issuance costs (3.2) (1.8) Gain on sale of properties and equipment Exploration, geologic and geophysical expense Other (0.7) (42.0) Changes in assets and liabilities (25.8) (10.2) Adjusted EBITDAX $ $ 57.8 Weighted-average diluted shares outstanding Adjusted EBITDAX per diluted share $ 1.97 $ /5/

57 Reconciliation of Non-U.S. GAAP Financial Measures Net income (loss) to adjusted net income (loss) Three Months Ended March 31, Net income (loss) $ 46.1 $ (71.5) Gain on commodity derivative instruments (80.7) (11.1) Net settlements on commodity derivative instruments Tax effect of above adjustments 30.0 (21.2) Adjusted net income (loss) $ (4.1) $ (37.0) Weighted-average diluted shares outstanding Adjusted earnings per diluted share $ (0.06) $ (0.89) Net cash from operating activities to adjusted cash flows from operations Three Months Ended March 31, Net cash from operating activities $ $ Changes in assets and liabilities (25.8) (10.2) Adjusted cash flows from operations $ $ /5/